Oil and gas is recovered by drilling into a hydrocarbon-bearing formation, for which purpose a drillstring terminated by a drill bit is used to form a wellbore. The drillstring formed from a series of connected drill pipe stands is rotated to remove formation ahead of the drill bit. Drilling mud or other fluid is pumped through the drillstring to cool the drill bit, and to aid the passage of drill cuttings from the base of the well to the surface, via an annulus formed between the drillstring and the wall of the wellbore.
Drilling operations may be hampered if the borehole formed by drilling is unstable. Typically, at predetermined intervals, the drillstring is pulled out of the bore hole, the bit is removed from the wellbore and a casing for the borehole comprising lengths of tubular casing sections coupled together end-to-end is run into the drilled wellbore and cemented in place. A smaller dimension drill bit is then inserted through the cased wellbore, to drill through the formation below the cased portion, to thereby extend the depth of the well. A smaller diameter casing is then installed in the extended portion of the wellbore and also cemented in place. If required, a downhole liner comprising similar tubular sections coupled together end-to-end may be installed in the well, fastened to and extending from the final casing section. The downhole liner may, or may not be, slotted or perforated.
The liner is typically supported upon the lower casing tubulars by use of a liner hanger and associated packer which provides an endurable seal between the casing and liner which must be capable of remaining fully functional downhole for many years. Before the packer can be set the positioned liner must be hung off upon the liner hanger. The liner hanger supports the full weight of the liner and maintains its position whilst the liner top packer seals are set. Since the operation is conducted deep downhole, it is not possible to inspect the operation directly, and so the success or otherwise of the setting operation has to be deduced by other means. For example it is important to gauge the integrity of the seals formed around the liner top, and to verify that the installed casing and liner tubulars form a fluid-tight circulation path and in particular to check that there is no leak associated with the liner hanger or the liner hanger packer.
The liner hanger usually provides for pressure sealing the hanger joint to the intent that the tubular bore passing through the casing into the liner is isolated from the annulus around the casing and liner within the borehole.
Since equipment for circulating fluids under pressure is routinely used on site, it is a known technique to utilise fluid pressure differentials downhole to predict or surmise conditions at a selected location around or within the tubular casing/liner extended length.
Thus pressure testing of the integrity of the liner top hanger seal is achievable by sealing the liner entry region with a removable seal (packer) being positioned within the annulus between a run-in tubular work string and a selected region of the internal wall of the liner.
In one such technique at least one packer is inserted into the well bore to seal off a portion of the annulus between the work string and the liner within the well bore just above the liner hanger. Fluid within the work string is displaced and a relatively low density fluid in comparison with the fluid already present in the wellbore is introduced to the work string thereby reducing hydrostatic pressure within the tubular string length. As a consequence of the pressure differential created, (assuming a sound packer seal) any imperfections in the liner hanger seals will admit overhead well bore circulation fluid resulting in an increase in pressure which can be monitored and used as an indication that liner top seal repairs are necessary.
A tool suitable for such a testing procedure is described in U.S. Pat. No. 6,896,064, which is hereby incorporated by reference.
That tool is adapted for mounting on a work string, and comprises a body with one or more packer elements and a sleeve, wherein the sleeve has or is associated with a shoulder and is moveable in relation to the tool body, wherein the shoulder co-operates with a formation, wherein upon co-operation with the formation, the sleeve can be moved relative to the tool body by setting down weight on the tool, and wherein movement of the sleeve relative to the tool body compresses the one or more packer elements.
The tool run into a pre-formed well bore on the work string. The pre-formed well bore is lined by a casing string and liner. The packer tool is run through the bore until the shoulder rests on the top of the liner. Weight is then set down on the work string and attached tool, until the one or more shear pins, shear.
Shearing of the shear pins, releases the sleeve from the body of the tool, and allows the sleeve to be moved relative to the body, by virtue of further weight set on the tool. Such shearing of the shear pins allows the sleeve to move in an axial direction relative to the body, whereby it compresses the one or more squeezable packer elements. Compression of the packer elements distorts them from an axially aligned oblong shape to a squat, radially extending squared shape. As a result of the change in configuration of the packer elements these come into contact with the casing thereby sealing the annulus between the casing and the tool.
Upon setting the packer tool an inflow negative test can be carried out to check the integrity of, for example, the cement bonds between tubular members and between casing connections. The test involves increasing pressure in the annulus above the packer (and liner top seal under test).
In order to achieve this, the work string can be filled with water or a similar low density fluid. This lower density fluid exerts a lower hydrostatic pressure within the drill pipe than the drilling fluid which is usually circulated through the pipe. If there are any irregularities in the cement bonds between casing members in the well bore, the drop in hydrostatic pressure created by circulation of a low density fluid will allow well bore fluids to flow into the bore lining. If this occurs an increase in pressure is recorded within the bore. This can be achieved by opening the drill pipe at the surface and monitoring for an increase in pressure which will occur if fluid flows into the bore. This allows any irregularities in the bore lining to be identified.
Such a technique is useful whenever it is possible to displace the existing wellbore fluid and create a pressure differential by introducing a fluid that is lighter than the fluid already present in the well bore.